1. Field of the Invention
This invention relates generally to energy conservation and greenhouse gas reduction, and to gasification based multi-generation apparatus employing advanced energy integration process schemes and methods of reducing energy utility requirements and greenhouse gas emissions in a gasification based multi-generation apparatus through advanced energy integration.
2. Description of the Related Art
Carbon-based feedstock-gasification plants and facilities for multi-commodities generation facilities have become a competitive option for syngas; combined heat and power plants and utilities; hydrogen production; sulfur production; and chilled water production for power generation, oil refining, gas-to-liquid conversion, and chemical and petrochemical industry applications.
Gasification is a process that converts carbonaceous materials into carbon monoxide, hydrogen and carbon dioxide. This is achieved by reacting the material at high temperatures (>700° C.), without combustion, with a controlled amount of oxygen and/or steam. The resulting gas mixture is called syngas (synthetic gas) or producer gas and is itself a fuel. The power derived from gasification and combustion of the resultant gas is considered to be a source of renewable energy if the gasified compounds were obtained from biomass.
An advantage of gasification is that using the syngas is potentially more efficient than direct combustion of the original fuel because it can be combusted at higher temperatures or even in fuel cells. Syngas can be burned directly in gas engines, used to produce methanol and hydrogen, or converted into synthetic fuel. Gasification can also begin with material which would otherwise have been disposed of such as biodegradable waste. Additionally, the high-temperature process can refine out corrosive ash elements such as chloride and potassium, allowing clean gas production from what would otherwise be considered problematic (dirty) fuels. Gasification of fossil fuels is currently used on industrial scales to generate electricity.
Power generators, oil refinery operators, and methanol and ammonia producers are looking for cleaner, reliable, and proven technology to generate power using coal, crude vacuum residues, biomass and other carbon-based fuels. Gasification is also an efficient means of converting low-value fuels and residuals into syngas. Syngas is used to produce power, steam, hydrogen, sulfur and basic chemicals such as methanol and ammonia. Gasification can also help solve the challenges of reliable power generation in industrial complexes.
Coal has traditionally powered much of the industrial world for more than a hundred years, and is still an abundant, low-cost resource. However, there is a growing concern over carbon emissions and their effect on the environment. As such, environmental regulations are demanding that coal be used in a cleaner, more efficient way to solve the world's growing demand for energy.
Integrated Gasification Combined Cycle, or IGCC. Integrated IGCC is a process that can turn coal and other carbon-based materials into a cleaner fuel that is used for more efficient power generation and raw material for chemical and oil refining facilities. For an example, gasification can turn coal into syngas gas. Syngas is also carbon capture ready, meaning it is possible to capture up to 90% of the CO2 generated from coal. To further increase efficiency and output, IGCC calls for taking any leftover heat or steam to power a second turbine. Gasification can also turn heavy refinery residues and petcoke into clean syngas (synthetic natural gas), creating more economic value from residues by converting into energy and valuable commodities like oxygen, nitrogen and hydrogen. It can provide an alternative source of natural gas in regions with high prices. Syngas output has more than enough energy value to power various users and enough energy value to run a Methanol Plant.
The process of producing energy using the gasification method has been in use for more than 180 years. During that time coal and peat were used to power these plants. Initially it was developed to produce town gas for lighting and cooking in 1800s, then later replaced by electricity and natural gas. It has also been used in blast furnaces, but has played a larger role since the 1920s in the production of synthetic chemicals. By 1945 there existed trucks, buses and agricultural machines that were powered by gasification.
In a gasifier, the carbonaceous material undergoes several different processes. The dehydration or drying process occurs at around 100° C. Typically the resulting steam is mixed into the gas flow and can be involved with subsequent chemical reactions, notably the water-gas reaction if the temperature is sufficiently high enough. The pyrolysis (or de-volatilization) process occurs at around 200-300° C. Volatiles are released and char is produced, resulting in up to a 70% weight loss for coal. The process is dependent on the properties of the carbonaceous material and determines the structure and composition of the char, which will then undergo gasification reactions. The combustion process occurs as the volatile products and some of the char, for example, reacts with oxygen to primarily form carbon dioxide and small amounts of carbon monoxide, which provides heat for the subsequent gasification reactions. The basic reaction is:C+O2→CO2.
The gasification process occurs as the char reacts with carbon and steam to produce carbon monoxide and hydrogen, via the following reaction:C+H2O→H2+CO.
The reversible gas phase water gas shift reaction reaches equilibrium very fast at the temperatures in a gasifier. This balances the concentrations of carbon monoxide, steam, carbon dioxide and hydrogen:CO+H2OCO2+H2.
A limited amount of oxygen or air is introduced into the reactor to allow some of the organic material to be “burned” to produce carbon monoxide and energy, which drives a second reaction that converts further organic material to hydrogen and additional carbon dioxide. Further reactions occur when the formed carbon monoxide and residual water from the organic material react to form methane and excess carbon dioxide. This third reaction occurs more abundantly in reactors that increase the residence time of the reactive gases and organic materials, as well as heat and pressure of the reaction. In more sophisticated reactors, catalysts are used to improve the reaction rates, resulting in a movement of the system to a state that is closer to the reaction equilibrium for a fixed residence time.
Several types of gasifiers are currently available for commercial use. They include: counter-current fixed bed, co-current fixed bed, fluidized bed, entrained flow, plasma, and free radical.
In the counter-current fixed bed (“up draft”) gasifier, a fixed bed of carbonaceous fuel, e.g., coal or biomass, through which the “gasification agent,” e.g., steam, oxygen and/or air, flows in counter-current configuration. The ash is either removed in the dry condition or as a slag. Gasifiers generally require that the fuel have a high mechanical strength and preferably non-caking so that it will form a permeable bed, although recent developments have reduced these restrictions to some extent. The throughput for this type of gasifier is relatively low. Thermal efficiency is high as the temperatures in the gas exit are relatively low. Tar and methane production, however, is significant at typical operation temperatures, so the product gas must be extensively cleaned before use. The tar can be recycled to the reactor.
In the gasification of fine, uncondensed biomass, it is necessary to blow air into the reactor by means of a fan. This creates very high gasification temperature, as high as 1000° C. Above the gasification zone, a bed of fine and hot char is formed, and as the gas is forced through this bed, most complex hydrocarbons are broken down into simple components of hydrogen and carbon monoxide.
In the co-current fixed bed (“down draft”) gasifier, the gasification agent gas flows in co-current configuration with the fuel, i.e., downwards, hence the name “down draft gasifier.” Heat is added to the upper part of the bed, either by combusting small amounts of the fuel or from external heat sources. The produced gas leaves the gasifier at a high temperature, and most of this heat is transferred to the gasification agent added in the top of the bed, resulting in energy efficiency on level with the counter-current type. Since all tars must pass through a hot bed of char in this configuration, tar levels, however, are much lower than in the counter-current type.
In the fluidized bed reactor, the fuel is fluidized in oxygen and steam or air. The ash is removed dry or as heavy agglomerates that de-fluidize. The temperatures are relatively low in dry ash gasifiers, so the fuel must be highly reactive; low-grade coals are particularly suitable. The agglomerating gasifiers have slightly higher temperatures, and are suitable for higher rank coals. Fuel throughput is higher than for the fixed bed, but not as high as for the entrained flow gasifier. The conversion efficiency can be rather low due to elutriation of carbonaceous material. Recycle or later combustion of solids can be used to increase conversion. Fluidized bed gasifiers are most useful for fuels that form highly corrosive ash that would damage the walls of slagging gasifiers. Biomass fuels, which typically contain high levels of corrosive ash, are a candidate for this type of gasifier.
In the entrained flow gasifier, a dry pulverized solid, an atomized liquid fuel or a fuel slurry is gasified with oxygen (much less frequent: air) in co-current flow. The gasification reactions take place in a dense cloud of very fine particles. Most types of coal are suitable for this type of gasifier because of the high operating temperatures and because the coal particles are generally well separated from one another. The high temperatures and pressures of this type of gasifier allow for a higher throughput. Thermal efficiency, however, is somewhat lower as the gas must be cooled before it can be cleaned according to existing technology. The high temperatures also result in the nonexistence of tar and methane in the product gas. However the oxygen requirement is higher than for the other types of gasifiers. All entrained flow gasifiers remove the major part of the ash as a slag as a result of the operating temperature being well above the ash fusion temperature.
Additionally, a smaller fraction of the ash is produced either as a very fine dry fly ash or as “black” colored fly ash slurry. Some fuels, in particular certain types of biomasses, can form slag that is corrosive to the ceramic inner walls that protect the gasifier outer wall. Some entrained flow type of gasifiers, however, do not possess a ceramic inner wall, but instead have an inner water or steam cooled wall covered with partially solidified slag. These types of gasifiers do not suffer from problems associated with corrosive slags.
Some fuels have ashes with very high ash fusion temperatures. In these types of fuels, a limestone additive is mixed with the fuel prior to gasification. Additionally of relatively small amounts of limestone will generally lower the fusion temperatures. In this gasifier, the fuel particles must be much smaller than for other types of gasifiers. As such, the fuel must be pulverized, which requires somewhat more energy than for the other types of gasifiers. The most energy consumption related to entrained flow gasification is not the milling of the fuel but the production of oxygen used for the gasification.
In a plasma gasifier, a high-voltage current is fed to a torch, creating a high-temperature arc. The inorganic residue is retrieved as a glass-like substance.
There are a large number of different feedstock types for use in the various types of gasifiers, each with different characteristics, including size, shape, bulk density, moisture content, energy content, chemical composition, + ash fusion characteristics, and homogeneity of all these properties. Coal and petroleum coke are typically used as feedstocks for many large gasification plants worldwide. Additionally, a variety of biomass and waste-derived feedstocks can be gasified, to include wood pellets and chips, waste wood, plastics, aluminum, municipal solid waste, refuse derived fuel, agricultural and industrial wastes, sewage sludge, switch grass, discarded seed corn, corn stover, and other crop residues.
Gasification of waste materials has several advantages over incineration. The necessary extensive flue gas cleaning can be performed on the syngas instead of the much larger volume of flue gas after combustion. Electric power can be generated in engines and gas turbines, which are much cheaper and more efficient than the steam cycle used in incineration. Even fuel cells may potentially be used, but these have rather severe requirements regarding the purity of the gas. Chemical processing of the syngas may produce other synthetic fuels instead of electricity. Some gasification processes treat ash containing heavy metals at very high temperatures so that it is released in a glassy and chemically stable form.
A major challenge for waste gasification technologies is to reach an acceptable (positive) gross electric efficiency. The high efficiency of converting syngas to electric power is counteracted by significant power consumption in the waste preprocessing, the consumption of large amounts of pure oxygen, which is often used as a gasification agent, and in gas cleaning. Another challenge when implementing the processes is how to obtain long service intervals, so that it is not necessary to close down the plant every few months for cleaning the reactor.
Syngas can not only be used for heat production and generation of mechanical and electrical power, but also as a raw material to many chemicals production. Like other gaseous fuels, use of syngas provides greater control over power levels when compared to solid fuels, leading to more efficient and cleaner operation. Syngas can also be used for further processing to liquid fuels or chemicals.
Gasifiers also offer a flexible option for thermal applications, because they can be retrofitted into existing gas fueled devices such as ovens, furnaces, boilers, etc., where syngas may replace fossil fuels. Notably, the heating values of syngas are generally considered to be around 4-10 MJ/m3. Industrial-scale gasification is currently mostly used to produce electricity from fossil fuels, such as coal, where the syngas is burned in a gas turbine. Gasification is also used industrially in the production of electricity, ammonia and liquid fuels (e.g., oil) using the Integrated Gasification Combined Cycles (IGCC), described previously. IGCC is also considered to be a more efficient method of CO2 capture as compared to conventional technologies. IGCC demonstration plants have been operating since the early 1970s and some of the plants constructed in the 1990s are now ready to enter commercial service.
In Europe, where the wood source is sustainable, 250-1000 kWe and new zero carbon biomass gasification plants have been installed in Europe that produce tar free syngas from wood and burn it in reciprocating engines connected to a generator with heat recovery. This type of plant is often referred to as a wood biomass CHP unit, and is typically used in small business and building applications.
Diesel engines can be operated on dual fuel mode using a producer gas, such as syngas. Diesel substitution of over 80% at high loads and 70-80% under normal load variations can be achieved. Spark ignition engines can operate on 100% gasification gas. Mechanical energy from the engines can be used, for an example, in driving water pumps for irrigation or for coupling with an alternator for electrical power generation.
While small scale gasifiers have existed for well over 100 years, there have been few sources to obtain a ready to use machine.
In principle, gasification can proceed from just about any organic material, including biomass and plastic waste, to produce syngas, which can be combusted. Alternatively, if the syngas is clean enough, it can be used for power production in gas engines, gas turbines or even fuel cells, or converted efficiently to dimethyl ether, methane, or a diesel like synthetic through fuel. In many gasification processes most of the inorganic components of the input material, such as metals and minerals, are retained in the ash. In some gasification processes, such as slagging gasification, for example, this ash has the form of a glassy solid with low leaching properties, but the net power production in slagging gasification is low or negative, and the costs can be higher.
Regardless of the final fuel form, gasification itself and subsequent processing neither directly emits nor traps greenhouse gases such as carbon dioxide. Power consumption in the gasification and syngas conversion processes can be significant, and can indirectly cause CO2 emissions; and in slagging and plasma gasification, the electricity consumption may even exceed the power production from the produced syngas.
Notably, the combustion of syngas or derived fuels emits exactly the same amount of carbon dioxide as would have been emitted from direct combustion of the initial fuel. Biomass gasification and combustion could, however, play a significant role in a renewable energy economy, because biomass production removes the same amount of CO2 from the atmosphere as is emitted from gasification and combustion. While other biofuel technologies, such as biogas and biodiesel are carbon neutral, gasification in principle may utilize a much larger variety of input materials and can be used to produce a much larger variety of output fuels.
Referring to FIG. 1, the carbon-based feedstock-gasification multi-generation facilities 50 generally includes the core plants, including a gasification plant 51, an acid gas removal plant 52, a hydrogen recovery plant 53, a sour water stripping plant 54, a condensate polishing plant 55, a sulfur recovery plant 56, and an air separation plant 57, described below, along with a power generation plant 58.
Gasification Plant (GP):
In a typical example, the gasification plant 51 in the carbon-based feedstock-gasification multi-commodities-generation facility 50 for power, steam, hydrogen and chilled water generation, can convert about 500 ton per hour vacuum residue (VR) or high sulfur fuel oil (HSFO) feed into carbon monoxide (CO), hydrogen (H2) and carbon dioxide (CO2). These gaseous products, collectively known as “syngas,” are subsequently used in a power generation plant block as fuel, and as feedstock to a hydrogen recovery unit (HRU) of a hydrogen recovery plant 53. The gasification process is a non-catalytic and auto-thermal process where the feedstock is partially oxidized with oxygen and steam to produce syngas.
Referring to FIG. 3, the syngas at about 1300° C. from a gasification reactor 61 is cooled in the syngas effluent cooler 63 (SEC). In this SEC 63, boiler feed water (BFW) is heated to generate high pressure (HP) steam by an economizer heat exchange unit BE1. Once the syngas leaves the SEC 63, it further cools in an economizer BE1 against BFW. Leaving the economizer BE1, the syngas still contains carbon and ash particles so it passes to the Soot Ash Removal Unit 65 (SARU). In order to remove all syngas solids content in the SARU 65, the syngas is contacted in a two-stage water wash. The first stage 67 is called the soot quench and the second stage 68 is the soot scrubber. The treated syngas leaves the soot scrubber 68 and passes to the acid gas removal plant 52. The SARU 65 also includes a soot separator 69 and a soot filter 70.
Within the gasification plant 51, the high pressure steam is produced by heat recovery from the hot syngas leaving the SEC 63. The other hot streams in the gasification plant are air-cooled to their target temperatures using coolers C1, C2. The oxygen required for gasification is preheated by high pressure steam stream produced in the plant using utility heat exchanger unit H1.
Acid Gas Removal Plant:
The Acid Gas Removal (AGRP) plant 52 is an integral part of any carbon-based feedstock-gasification multi-commodities-generation facilities, e.g., power, steam, hydrogen, sulfur and chilled water generation, and treats the syngas produced from the upstream Gasification Unit or Plant 51.
Referring to FIG. 5, the AGRP 52 normally includes several identical trains including a reaction section 81 and a separation section 82 with back-up to guarantee the carbon-based feedstock-gasification desired facility availability level. Note, only one train is shown in the figure. Each train has a HCN/COS (HCN and/or COS) Hydrolysis unit 83 located in the reaction section 81 and typically comprising a contaminant hydrolysis (catalytic) reactor 85, and a Sulfinol-M unit 91 located in the separation section 82 and typically comprising a contaminant absorber column 92, a solvent regenerator 93, and an enrichment contractor 94, for example. The HCN/COS Hydrolysis unit 83 removes contaminants such as Hydrogen® Cyanide (HCN) and Carbonyl Sulfide (COS). These contaminants are formed in the gasification plant 51 and may cause amine degradation to the downstream Sulfinol-M unit 91. The Sulfinol-M unit 91 is a regenerative amine process to remove H2S, CO2, COS, mercaptans and organic sulfides/disulfides from the gas streams. These harmful contaminants are either in the syngas stream from the gasification plant 51 or formed in the HCN/COS Hydrolysis unit 83. After the syngas is treated in the acid gas removal plant 52, it is routed either to the Hydrogen Recovery Plant 53 for high purity hydrogen production or the Power Generation plant 58 for steam production and power generation.
In the acid gas removal plant 52, the syngas feed 101 from the gasification plant 51 is preheated by the reactor effluent 102 in reactor feed-effluent heat exchanger BE3 and the reactor effluent 102 is further cooled by cold polished condensate stream 103 in condensate-reactor effluent heat exchanger BE4 which recovers heat from the bottom stream effluent at 102 of the HCN/COS hydrolysis main catalytic reactor 85. A HCN/COS syngas knockout (KO) drum 95 collects sour water condensed as a result of a reduction in temperature of the effluent bottom stream 102 of the contaminant hydrolysis reactor 85 by reactor effluent-condensate heat exchanger BE4 and cooler/chiller C8 prior to entering the contaminant absorber 92.
Heat recovery is also utilized between the lean solvent bottom stream 105 from the Sulfinol-M regenerator unit 93 and the rich solvent bottom stream 106 of the main absorber section 92 in the rich solvent-lean solvent bottom streams heat exchanger BE5. Hot utilities, such as high pressure steam and low pressure steam via hot utility heat exchanger units H3, H4, H5, are used to further heat process steams to their target temperatures. Cold utilities, such as air, cooling water and chilled water through cold utility exchangers C8, C9, C10, C11, C12, are utilized to cool process streams to their desired target temperatures.
Recognized by the inventor, however, is that although the technology of acid gas removal on a standalone basis is mature in the gas processing industry, its energy integration with the gasification, power generation and condensate handling plants, is not optimally addressed in the public domain.
Hydrogen Recovery Plant:
The hydrogen recovery plant (HRP) 53 in the carbon-based feedstock-gasification multi-commodities generation facility 50 for power, steam, hydrogen and chilled water generation, upgrades the hydrogen from the treated syngas leaving the acid gas removal plant 52. The plant 53 generally includes a membrane pre-treatment section 111, gas separation membrane unit 112, a compressor 113, and a pressure swing adsorption (PSA) unit 114.
Referring to FIG. 7, the Syngas upon entering the HRP 53 is first treated in the membrane pre-treatment unit 111. In this membrane pre-treatment unit 111, all liquids in the treated syngas feed are removed in its feed filter coalescer (not shown). The feed is then heated in a steam heater H2, for example, to the operation temperature of a gas separation membrane unit 112. The gas separation membrane unit 112 separates the available feed gas into two streams. One stream is available at high pressure and the other stream is available at low pressure. The high-pressure stream leaving the gas separation membrane unit 112 is called the non-permeate and is available at a pressure equal to the pressure in the feed minus the friction losses in the piping and membrane modules. The non-permeate directly feeds the power generation plant 58. The low-pressure stream leaving the gas separation membrane unit 112 is called the “permeate”. The permeate design pressure has been selected so that there is an optimum separation (i.e., hydrogen enrichment) of the feed gas proceeding to the membranes 112.
Downstream of the membranes 112, this permeate is first cooled and made free of liquids in the permeate knock-out drum (not shown). The permeate then flows to the permeate compressor 113 in order to pressurize this hydrogen rich stream to such a level that it is sufficient to pass through a PSA unit 114 before supplying the end user such as, for example, a finery with hydrogen.
Downstream of the permeate compressor 113, the gas is first cooled in water cooler C3 and then consequently in a chilled water cooler (not shown). The stream leaving the permeate compressor's after coolers (not shown) is then made free of liquids in the PSA feed knock-out drum (not shown). The gas leaving the PSA feed knock-out drum then enters the PSA unit 114. This PSA unit 114 separates the permeate gas into a high-purity hydrogen stream and a PSA tail gas stream. The PSA tail gas is used as fuel for power generation in the power generation plant 58. The high-purity hydrogen stream is the final product of this hydrogen recovery plant 53 and is available at the required pressure for the end user, such as an oil refinery.
Regarding the energy requirements within the HRP 53, there is a hot stream to be cooled by cooling unit C3 and a cold stream to be heated by steam heater H2 by using cold and hot utilities. Hence heating and cooling duties are required. Low pressure steam is used to heat the treated syngas coming from the AGRP after it has been made free of liquids. The permeate process stream in the conventional design is cooled using cooling water. The stream leaving the permeate compressor 113 is first cooled using cooling water and then it gets chilled using chilled water.
Sour Water Stripper Plant (SWSP):
The SWSP 54 is an integral part of any carbon-based feedstock-gasification multi-commodities generation facility 50. Referring to FIG. 9, the SWSP 54 receives sour water streams that include the excess filtrate water from the soot water filtration from the soot filter of the gasification plant 51, and the condensate and sour waters from the acid gas removal plant 52, sulfur recovery plant 56, and flare unit (not shown). These streams are collected in the waste water collection tank (not shown) of the sour/waste water stripping unit, which includes a sour water stripper column 117. The SWSP 54 also receives the sour gas stripped and released from the soot water flash vessel.
In the sour water stripper 117, the sour water from SWSP tank is stripped counter-currently with live steam. The ascending flow of steam strips the sour components, primarily carbon dioxide (CO2), hydrogen sulfide (H2S) and ammonia (NH3), from the descending sour water stream. A caustic solution (NaOH) is also added at an intermediate point in the stripper 117 bottom to enhance ammonia stripping. The temperature of the overhead column should be maintained well above 80° C. in order to avoid plugging in the upper section of the column caused by the formation of NH4HS and NH4HCO3 salts/solids. The condensing sour gas stream leaves over the top and the stripped waste water stream leaves at the bottom.
The overhead vapors from the stripper 117 and from soot water flash vessel (not shown) are partially condensed in the stripper off-gas air cooler (not shown) before being routed to the stripper reflux accumulator (not shown). The overhead condenser (not shown) of the stripper off-gas air cooler maintains the exit temperature at minimum 100° C. including in seasons with low ambient temperatures. The temperature is an optimum of forming salts and corrosion in the stripper off-gas air cooler. In the stripper reflux accumulator, the liquid and the non-condensed vapors are separated. The stripper reflux pump (not shown) delivers/pumps the liquid back to the rectifying section in the top of the column. The produced sour gas stream, having low water content, cooled by a cooling utility exchanger C4, is routed to the sulfur recovery plant 56 and at upset conditions to the sour flare.
The waste water stream leaving the bottom of the stripper 117 is cooled by waste water air cooler C5 and waste water cooler C6, and then routed to the off-site battery/bound limit (OSBL) for further treatment in a bio-treatment plant. The wastewater still contains dissolved ash components, which makes the effluent water from the bottom of the stripper 117 unfit for reprocessing as make-up/boiler water. For biological treatment reasons, the wastewater is cooled to minimum achievable temperature given the cooling capabilities of air cooling and closed loop cooling water (about 45° C.).
Condensate Polishing Plant:
The carbon-based feedstock-gasification multi-commodities generation facility 50 includes a condensate collection and polishing plant 55 that collects and polishes condensate from the whole facility 50. Referring to FIG. 11, the condensate polishing plant 55 stores the polished condensate in the condensate storage tank 121 and sends the polished condensate to the power generation plant 58 to make boiler feed water (BFW) for steam and power generation. Therefore, the condensate polishing system is linked to all the site-wide process plants in the carbon-based feedstock-gasification multi-commodities generation facility 50.
Referring to FIG. 11, atmospheric condensate flash drum(s) 122 collects the carbon-based feedstock-gasification multi-commodities generation facility condensate and uses an air cooler (not shown) as a trim steam condenser. In turn, low pressure (LP) condensate collected from various units in the carbon-based feedstock-gasification multi-commodities generation facility 50 is cooled with demineralized water in heat exchangers BE2. It is further cooled by trim cooler(s) C7. The condensate from the atmospheric condensate flash drum 122 mixes with the LP condensate collected from various other units in the carbon-based feedstock-gasification multi-commodities generation facility 50. This condensate is then polished in the condensate polisher unit 123. The carbon-based feedstock-gasification multi-commodities generation facility polished condensate is treated by neutralizing amine for pH adjustment and then stored in the condensate storage tanks 121. Such condensate is then pumped to the power generation plant to make boilers/economizers BE1/heat recovery steam generators feed water.
Sulfur Recovery Plant:
Referring again to FIG. 1, the sulfur recovery plant 56 (components not shown in detail) in the carbon-based feedstock-gasification multi-commodities generation facility 50, as would be understood by one of ordinary skill in the art, produces sulfur via processing the acid gas streams leaving the acid gas removal plant(s) 52 and the Claus off-gas treating process. These acid gas streams are combined and routed to amine acid gas knock-out drum to separate entrained water. In order to increase the main burner temperature for ammonia destruction, the acid gas from knock-out drum is divided into a main stream which feeds the main burner and a minor stream which flows to the main combustion chamber. Before entering the main burner the main amine acid gas stream flows through the amine gas pre-heater where it is heated to 240° C. against HP Steam. Off-gas from the sour water stripper (SWS) 117 flows to the SWS 117 gas knock-out drum where any sour water liquid is removed. It then flows to the SWS 117 gas pre-heater where the gas is also heated to about 240° C. by HP steam.
The amine acid gas and the SWS 117 off-gas are then combined and become the feed gas for the Claus main burner. Pure oxygen is supplied to the main burner to maintain the temperature in the main combustion chamber sufficiently high. The oxygen supplied to the burner is exactly sufficient to accomplish the complete oxidation of all hydrocarbons and ammonia present in the feed gas. The minor acid gas stream is introduced to the back end of the combustion chamber to mix and react with the hot gasses from the front end prior to entering the Claus waste heat boiler.
The process gas is cooled with boiler feed water thereby generating saturated HP steam. Part of the steam is used for heating the process gas in the re-heaters and the surplus is superheated in the steam super-heater in the incinerator section before being fed into the HP steam grid. The process gas is introduced into the first sulfur condenser, where it is further cooled and the sulfur vapor is condensed while generating LP steam. Liquid sulfur is drained to the sulfur collecting vessel via first sulfur lock. The process gas outlet temperature is determined by the condenser design and the pressure of the LP steam generated in the condenser.
Further conversion into sulfur is achieved by using a catalytic process in two subsequent converters containing highly reactive catalysts. Prior to entering first Claus converter, the process stream is heated in the first Claus re-heater to the optimum temperature for catalytic conversion. The effluent gas of the first converter is passed to second Sulfur Condenser where the sulfur is condensed and drained to the collecting vessel via second sulfur lock. After the first stage, approximately 85-90% of the sulfur present in the feed gas has been recovered. In order to increase the recovery rate, a second converter stage has been incorporated, consisting of second Claus re-heater, second Claus converter, and third sulfur condenser. The condensed sulfur is drained via third sulfur lock. After the second converter stage approximately 95% of the sulfur has been recovered. The Claus tail gas is routed via coalescer to the “Claus off-gas treating” process section.
Any produced sulfur is drained via fourth sulfur lock. The heat released by cooling the gas and condensing the sulfur results in the production of LP steam. The sulfur as it is produced in the Claus section is routed to the sulfur degassing section that reduces the hydrogen sulfide (H2S) content in the stripping section of the sulfur degassing vessel. The sulfur collecting vessel is provided to obtain the gravity draining from the sulfur condensers. Prior to entering the collecting vessel, the sulfur from the locks is cooled in sulfur cooler. The Claus tail gas is reheated to about 210° C. in the re-heater prior to entering the converter, which contains a reducing catalyst. In the converter all sulfur components are catalytically converted into H2S by the reducing components in the process gas. The reactions in the converter are exothermic, so the gas temperature rises.
The process gas exiting the converter is cooled to approximately 43° C. by direct contact cooling with a counter-current flow of water in quench column. The water vapor in the process gas is partly condensed and mixed with the circulating cooling water. The excess water (condensed) is sent to sour water collecting drum. The overhead gas from the quench column is routed to the absorber 92. The circulating water is cooled from approximately 74 to 42° C. in quench water air cooler followed by quench water trim cooler and sent to the top of the quench column. In the Absorber 92, the process gas is contacted counter-currently with a lean 40 wt. % MDEA solution supplied to the top of the column. Virtually all H2S is removed from the gas and only approximately 10-20% of the carbon dioxide (CO2) present in the process gas is co-absorbed in the solvent.
The treated gas leaving the absorber 92 (so-called off-gas) is sent to the incinerator section. The rich solvent leaving the absorber 92 bottom is heated in lean/rich exchanger and sent to the regenerator 93. In the lean/rich heat exchanger, the cold rich solvent is heated by the hot lean solvent from the regenerator 93 bottom. In the regenerator 93, H2S and CO2 are stripped from the solvent. The required heat is delivered by reboiler, in which lean solvent is re-boiled using LP steam. The released H2S, CO2 and residual steam are routed from the regenerator 93 top via overhead condenser to the regenerator 93 reflux drum. The condensed water is separated in this drum from the acid gas and the gas is recycled to the front of the Claus section. Lean solvent from the regenerator 93 bottom proceeds to the lean/rich exchanger. The lean solvent is further cooled in lean solvent trim cooler against cooling water to about 45° C., after which a part of the solvent is passed through lean solvent filter. To obtain the required lean solvent temperature of 30° C., the lean solvent is further cooled in lean solvent chilled cooler against chilled water. The cooled lean solvent is then routed as reflux to the absorber 92. The tail gas and the vent gas from the sulfur degassing contain residual H2S and other sulfur compounds, which cannot be released directly to atmosphere. These gases are therefore thermally incinerated in the incinerator chamber at 850° C. to convert residual H2S and sulfur compounds into sulfur dioxide. The gases to be incinerated are heated by mixing with hot flue gas, obtained by combustion of fuel gas in the incinerator burner. The flue gas leaving the incinerator chamber is cooled first in the incinerator waste heat boiler, prior to entering the HP Steam super-heater. Here the flue gas is further cooled to approximately 300° C. thereby superheating the surplus of HP steam after which the flue gas is discharged to the atmosphere via stack.
Air Separation Plant:
The air separation unit (ASU) 57 (not shown in detail) of the IGCC complex takes ambient air and produces near-pure oxygen and nitrogen streams. The oxygen is used in the Gasifier Unit (GU) and Sulfur Recovery Unit (SRU), and the nitrogen is used in the SRU and Power Block. In total, about 770 tph oxygen at 35° C. and 80 barg is needed, and about 2500 tph nitrogen is produced alongside for about 500 tph vacuum residue feed for the gasification plant 51. The typical double-column ASU 57 is usually used on site in the carbon-based feedstock-gasification multi-commodities generation facility 50.
Carbon-based-feedstock-gasification plants for multi-commodities generation facilities have become one of the competitive options for syngas; combined heat and power; hydrogen; sulfur; chilled water production for power generation, oil refining, Gas-to-Liquid, chemical and petrochemical industries' applications.
Accordingly, recognized by the inventor is that it would be beneficial to numerous industries such as combined heat and power generation, oil refining, and chemicals production industries, to make carbon-based feedstock-gasification multi-generation facilities significantly more energy efficient and to reduce heating energy-utility-based GHG emissions, while preserving its operability and “retrofitability” due to future expansion needs for more power and heat generation; more syngas production for chemical industries, and/or more hydrogen for oil refining.
The inventor has also recognized that it will be beneficial to such industries to make such very important carbon-based feedstock-gasification facilities, comprising many integrated plants for multi-commodities generation, significantly more “green” via enhanced energy efficiency and reducing energy-based GHG emissions by 30%, or more, with a view towards operability with even more involved plants integration, and retrofitability due to future expansions in production capacities.
The inventor has further recognized the need for modifications to various configurations of carbon-based-feedstocks-gasification for multi-generation facilities' plants configurations to make the whole multi-generation facility energy system, which includes several plants and/or facilities, more efficient, less polluting, operable at different plants'-specific operating modes, and readily retrofitable upon future expansions.
For such purpose, the inventor has recognized the need to modify carbon-based-feedstock-gasification for multi-generation facilities that produce, for example, power; hydrogen; sulfur; steam; syngas; and chilled water, to be more energy integrated to make it dramatically more energy efficient and less polluting due to energy-based GHG emissions, as well as operable and retrofitable upon its future expansion. These facilities can include gasification, acid gas removal, hydrogen recovery, condensate handling, sour water stripping, air separation, power generation and sulfur recovery plants or facilities.
Further recognized by the inventor, is the need to modify various configurations of carbon-based feedstock-gasification multi-generation facilities that combine new energy efficient configurations that result in significant energy and energy-based GHG emissions reductions of about 30% or more in the carbon-based feedstock-gasification plants in multi-generation facilities.